Method for primary cementing a well using a drilling mud composition which may be converted to cement upon irradiation

ABSTRACT

This application discloses a process for drilling and primary cementing a well using a drilling fluid containing a polymeric material which may be cemented into a well cement by irradiation with a suitable radioactive source.

RELATED APPLICATIONS

This application is related to the following applications filed the samedate as is this one:

"Primary Cementing Technique" by Novak P.M. 79.104

"A Settable Drilling Fluid" by Novak P.M. 79.103

"Novel Drilling Mud Composition" by Novak and Talukder P.M. 82.18

"Alkadiene - Acrylic - Vinyl Compound Copolymers" by Novak, Talukder,and Sinclair P.M. 81.52.

BACKGROUND OF THE lNVENTION

1. Object of the Invention

This invention relates to a method for primary cementing a well using acomposition of matter containing a polymeric compound which is useful asa drilling mud and may be converted to a cement upon irradiation with aproper source.

2. Field of the Invention

The process of searching for oil and gas is fraught with risk.Approximately three out of every four wells drilled in the United Statesare dry holes. Even in the instance when a well is found to havepenetrated a subterranean formation capable of producing an economicamount of hydrocarbon, the well must be carefully completed afterdrilling has ended or less than the maximum amount of hydrocarbon willbe produced. One problem caused by the improper well completion step ofcementing is subterranean movement of gas from a high pressure formationto another formation of lower pressure. The gas lost in this way maynever be recovered. This invention solves many of the problemsassociated with poor cementing procedures by converting the fluid knownas "drilling mud" directly into a hardened cement. Drilling mud is thefluid typically used during the drilling of a well to lubricate and coolthe bit as well as remove rock cuttings from the borehole. Drilling mudis usually displaced in a discrete step by a cement slurry after theborehole is lined with steel casing.

The process of drilling a well followed by the steps of casing andcementing it are described below.

a. Drilling the Well

In conventional rotary drilling, a borehole is advanced down from thesurface of the earth (or bottom of the sea) by rotating a drill stringhaving a drill bit at its lower end. Sections of hollow drill pipe,usually about 30 feet long, are added to the top of the drill string,one at a time, as the borehole is advanced in increments.

In its path downward, the drill bit may pass through a number of stratabefore the well reaches the desired depth. Each of these subsurfacestrata has associated with it physical parameters, e.g., fluid content,hardness, porosity, pressure, inclination, etc., which make the drillingprocess a constant challenge. Drilling through a stratum producessignificant amounts of rubble and frictional heat; each of which must beremoved if efficient drilling is to be maintained. In typical rotarydrilling operations, heat and rock chips are removed by the use of aliquid known as drilling mud. As noted above, drill strings are usuallymade up of sections of hollow pipe terminated by a drill bit. Drillingmud is circulated down through the drill string, out through orifices inthe drill bit where the mud picks up rock chips and heat, and returns upthe annular space between the drill string and the borehole wall to thesurface. The mud is sieved on the surface, reconstituted, and pumpedback down the drill string.

Drilling mud may be as simple in composition as clear water, but morelikely it is a complicated mixture of clays, thickeners, and weightingagents. The characteristics of the drilled geologic strata and, to someextent, the nature of the drilling apparatus determine the physicalparameters of the drilling fluid. For instance, the drilling mud must becapable of carrying the rock chips to the surface from the drillingsite. Shale-like rocks often produce chips which are flat. Sandstonesare not quite so likely to produce a flat chip. The drilling fluid mustbe capable of removing either type of chip. Conversely, the mud musthave a viscosity which will permit it to be circulated at high rateswithout excessive mud pump pressures.

In the instance where a high pressure layer, e.g., a gas formation, ispenetrated, the density of the drilling mud must be increased to thepoint such that the hydrostatic or hydraulic head of the mud is greaterthan the downhole (or "formation") pressure. This prevents gas leakageout into the annular space surrounding the drill pipe and lowers thechances for the phenomenon known as "blowout" in which the drilling mudis blown from the well by the formation gas. Finely ground barite(barium sulfate) is the additive most widely used to increase thespecific gravity of drilling mud; although, in special circumstances,iron ore, lead sulfide ferrous oxide, or titanium dioxide may also beadded.

In strata which are very porous or are naturally fractured and whichhave formation pressures comparatively lower than the local pressure ofthe drilling mud, another problem occurs. The drilling fluid, because ofits higher hydrostatic head, will migrate out into the porous layerrather than completing its circuit to the surface. This phenomenon isknown as "lost circulation". A common solution to this problem is to adda lost circulation additive such as gilsonite.

Fluid loss control additives may be included such as one containingeither bentonite clay (which in turn contains sodium montmorillonite) orattapulgite, commonly known as salt gel. If these clays are added to thedrilling mud in a proper manner, they will circulate down through thedrill string, out the drill bit nozzles, and to the site on the boreholewall where liquid from the mud is migrating into the porous formation.Once there, the clays, which are microscopically plate-like in form,form a filter cake on the borehole wall. Polymeric fluid control agentsare also well known. As long as the filter cake is intact, very littleliquid will be lost into the formation.

The properties required in drilling mud constantly vary as the boreholeprogresses downward into the earth. In addition to the various materialsalready noted, such substances as tannin-containing compounds (todecrease the mud's viscosity), walnut shells (to increase the lubricityof the mud between the drillstring and the borehole wall), colloidaldispersions, e.g., starch, gums, carboxy-methyl-cellulose (to decreasethe tendency of the mud to form excessively thick filter cakes on thewall o: the borehole), and caustic soda (to adjust the pH of the mud)are added as the need arises.

The fluid used as drilling mud is a complicated mixture tailored to do anumber of highly specific jobs.

Once the hole is drilled to the desired depth, the well must be preparedfor production. The drill string is removed from the borehole and theprocess of casing and cementing begins.

b. Casing and Cementing the Well

It should be apparent that a well that is several thousand feet long maypass though several different hydrocarbon producing formations as wellas a number of water producing formations. The borehole may penetratesandy or other unstable strata. It is important that in the completionof a well each producing formation be isolated from each of the othersas well as from fresh water formations and the surface. Propercompletion of the well should stabilize the borehole for a long time.Zonal isolation and borehole stabilization are also necessary in othertypes of wells, e.g., storage wells, injection wells, geothermal wells,and water wells. This is typically done, no matter what the type ofwell, by installing metallic tubulars in the wellbore. These tubularsknown as "casing", are often joined by threaded connections and cementedin place.

The process for cementing the casing in the wellbore is known as"primary cementing". In an oil or gas well, installation of casingbegins after the drill string is "tripped" out of the well. The wellborewill still be filled with drilling mud. Assembly of the casing is begunby inserting a single piece of casing into the borehole until only a fewfeet remain above the surface. Another piece of casing is screwed ontothe piece projecting from the hole and the resulting assembly is loweredinto the hole until only a few feet remain above the surface. Theprocess is repeated until the well is sufficiently filled with casing.

A movable plug, often having compliant wipers on its exterior, is theninserted into the top of the casing and a cement slurry is pumped intothe casing behind the plug. The starting point for a number of wellcements used in that slurry is the very same composition first patentedby Joseph Aspdin, a builder from Leeds, England, in 1824. That cement,commonly called Portland cement is generally made up of:

    ______________________________________                                        50%            Tricalcium silicate                                            25%            Dicalcium silicate                                             10%            Tricalcium aluminate                                           10%            Tetracalcium aluminoferrite                                     5%            Other oxides.                                                  ______________________________________                                    

API Class A, B, C, G and H cements are all examples of Portland cementsused in well applications. Neat cement slurries may be used in certaincircumstances; however, if special physical parameters are required, anumber of additions may be included in the slurry.

As more cement is pumped in, the drilling fluid is displaced up theannular space between the casing and the borehole wall and out at thesurface. When the movable plug reaches a point at or near the bottom ofthe casing, it is then ruptured and cement pumped through the plug andinto the space between the casing and the borehole wall. Additionalcement slurry is pumped into the casing with the intent that it displacethe drilling mud in the annular space. When the cement cures, eachproducing formation should be permanently isolated thereby preventingfluid communication from one formation to another. The cemented casingmay then be selectively perforated to produce fluids from particularstrata.

However, the displacement of mud by the cement slurry from the annularspace is rarely complete. This is true for a number of reasons. Thefirst may be intuitively apparent. The borehole wall is not smooth butinstead has many crevices and notches. Drilling mud will remain in thoseindentations as the cement slurry passes by. Furthermore, as notedabove, clays may be added to the drilling mud to form filter cakes onporous formations. The fact that a cement slurry flows by the filtercake does not assure that the filter cake will be displaced by theslurry. The differential pressure existing between the borehole fluidand the formation will tend to keep the cake in place. Finally, becauseof the compositions of both the drilling mud and the cement slurry, theexistence of non-Newtonian flow is to be expected. The drilling mud mayadditionally possess thixotropic properties, i.e., its gel strengthincreases when allowed to stand quietly and the gel strength thendecreases when agitated. The combination of these effects createsboundary layer conditions which hinder the complete displacement of thedrilling mud from the annular space.

Several remedial and preventative steps may be taken to assist inremoval of drilling mud from the annular space. Long wire bristles or"scratchers" may be placed at intervals along the casing string as it isinserted into the hole. These devices have the direct beneficial effectof removing filter cakes from the borehole wall and providing animproved bonding site for the set cement. However, because of the flowcharacteristics of the cement slurry and the drilling mud, thescratchers are not completely effective in causing the mud to displace.

Similarly, a device known as a "centralizer" can be added to the casingstring to centralize the casing and improve the flow around the string.Although centralizers are helpful in preventing quiescent areas, theborehole does not have a perfect interior surface and dead spots willoccur in, e.g., dog-legs in the hole.

Other methods of aiding in the displacement operation, have beenattempted and each has its own benefits and detriments. These methodsinclude preflushes, spacers, additives to reduce drilling mud viscosity,abrasive materials to erode the filter cake, and high apparent viscositycement to displace drilling mud in a piston-like motion. None of theknown methods is completely effective in removing mud from the boreholewall.

One goal of the art has been to dispense with the necessity ofdisplacing the drilling mud by utilizing but a single fluid capable ofperforming the functions of both the mud and the cement. The benefits ofsuch a multifunctional fluid are apparent. The requirements that thefilter cake be removed from the borehole wall and that the mud be takenfrom the imperfections in the wall are therefore obviated. A few patentsdisclose methods for converting drilling mud to cement and are discussedbelow. However, none of these disclosures suggest a drilling mud whichis used per se as the well cement. The disclosures normally teach theaddition of some other material to the mud prior to its use as a cement.None of the references shows the conversion of mud to cement byirradiation in the well.

A method of converting drilling mud to a cement slurry is disclosed inU.S. Pat. No. 3,168,139, issued to Kennedy et al on Feb. 2, 1965.Kennedy et al teaches the straightforward step of adding a hydrauliccement, preferably a Portland cement, to the drilling mud to form acement slurry. Kennedy et al does not suggest using the cement slurryso-formed as a drilling fluid. Kennedy et al also notes at Column 13,line 32 et seq that "less channeling through the set cement occurs thanwhen conventional cementing slurries are employed". The efficiency ofthe Kennedy et al process is therefore not assured.

The patent to Cunningham et al, U.S. Pat. No. 3,409,093, issued Nov. 5,1968, teaches the use of a known cement slurry as the drilling fluid.This process is said simultaneously to produce an impenetrable filtercake on the borehole wall and a strong cement sheath on the wallscapable of stabilizing the borehole wall. It should be apparent thatclose control of setting rate by retarder concentration and watercontent (via inclusion of water and water-loss additives) must bemaintained using this process lest the cement slurry set and seize thedrill string. It should also be apparent that the drilling fluiddisclosed by Cunningham et al will be useful as a drilling fluid onlyfor a short time.

Tragesser, U.S. Pat. No. 3,557,876, issued Jan. 26, 1971, teaches adrilling mud which can be converted, when desired, to a cementitiousmaterial by the addition of an alkaline earth oxide such as calcium,strontium or barium oxide. The particular drilling mud involvedcomprises water, collodial clay, various conventional additives, and asubstance known as pozzolan. Pozzolan is a siliceous material (generallyabout 50 percent silicon oxide) containing various percentages of otheroxides such as magnesium oxide, aluminum oxide, or iron oxide. Thesematerials are said to form a cementitious material when reacted with analkaline earth oxide in the presence of water at the temperatures founddownhole in a well. There is no assurance that adequate mixing betweenthe disclosed drilling mud and the alkaline earth oxide will occur inthe well. Without proper mixing, quiescent volumes may remain within thewell and prevent attainment of an acceptable cement job.

The disclosure in Harrison et al, U.S. Pat. No. 3,605,898 issued Sept.20, 1971, relates to a hydraulic cement composition containing a settingretardant known as a heptolactone, preferablyD-gluco-D-guloheptolactone. The composition is said to be usable as adrilling mud as long as the retardent is effective. A water solublepolyvalent metal salt, preferably CaCl₂, is added to the mud to effect aconversion into cement.

The teachings in Miller et al, U.S. Pat. No. 3,887,009, issued June 3,1975, relate to a clay-free magnesium-salt drilling fluid. Such fluidsare said to typically contain 15 to 60 pounds of magnesium sulfate perbarrel of drilling mud, from 20 to 70 pounds per barrel dolomite, about3 to 15 pounds of calcium oxide per barrel, and 4 to 10 pounds of gypsumper barrel. In order to form a cement from this drilling mud, sufficientmagnesium oxide, magnesium sulfate and dolomite or magnesium carbonateare added to produce a magnesium oxysulfate cement. Again, control ofthe concentration of the added material appears to be critical.

None of the disclosures of Tragesser, Harrison et al or Miller et aleliminate the step of displacing the drilling fluid from the well.

The process disclosed herein does not require the sequential addition ofvarious materials as the time for cementing approaches, although it isacceptable to do so. The step which initiates the conversion of thedisclosed composition from drilling mud to cement is the irradiation ofthat composition in the well. The cross-linkable polymers contained inthe polymeric composition thereafter crosslink forming a strong setcement.

There are, of course, other known compositions containing polymerizablecompounds which have been placed in wells for a variety of reasons.

A disclosure of one such composition is found in Perry et al, U.S. Pat.No. 3,114,419 issued Dec. 17, 1963. Perry et al suggests a "method forpolymerizing liquid-resin forming materials suitable for use in wellbores penetrating permeable subterranean formations". The preferredmethod uses radiation to copolymerize an alkylidene bisacrylamide withan ethylenic monomer. Perry et al teaches that the polymeric compositionis made up so as to have a specific gravity between 1.07 and 1.18(Column 4, lines 48 et seq). The specific gravity may be adjusted by theaddition of non-ionizing organic weighting agents such as sugar orglycerol. The composition should retain some water solubility to beeffective (Column 3, lines 43 et seq). The composition is pumped to theformation to be plugged by first pumping fresh water down the casingfollowed by the polymeric composition (Column 5, line 65 et seq). Anamount of salt water is then pumped in until the composition is placedat the site of the porous formation. Because the specific gravity of thecomposition is between that of the overlying fresh water and theunderlying salt water, it will stay in place. A radioactive source isthen inserted into the well, to effect copolymerization and seal thepermeable formation. Perry et al additionally discloses the use ofsimilar processes to seal permeable formations when using a gas as thedrilling fluid (Column 6, line 46 et seq and Example V) and to plug apermeable formation in a water flood injection well (Example VI).

Perry et al does not disclose or suggest the use of drilling mudscontaining polymeric materials which can be converted to cement byirradiation in the well.

Other disclosures relating to the use of irradiated polymers in wellliquids can be found in U.S. Pat. Nos. 3,830,298, 3,872,923, 3,877,522,and 3,973,629 each issued to Knight et al. Another disclosure ofradiation induced polymerization may be found in Canadian Pat. No.1,063,336 to Ressaine et al. Each of these disclosures relates to aparticular use of a polymerized "acrylamide and/or methacrylamide andacrylic acid, methacrylic acid, and/or alkali metal salts thereof" in anumber of different ways, e.g., as a water loss additive in cement, as aplugging medium in a porous formation, etc. However, each of thedisclosures deals with a polymeric composition which is irradiated priorto being placed in a well.

c. Completing the Well

After the casing is cemented in place, a well is prepared forhydrocarbon production using a number of separate steps. A perforationtool is commonly lowered within the cemented casing to the region of aproducing formation. The perforation tool is a device which often isconstructed of a number of guns which produce holes through the casingand its enclosing cement and into the producing formation. The interiorof the casing is thereafter in open communication with the formation.

Other completion steps may involve fracturing to increase wellproductivity, installing screens to exclude sand from the well bore, andinstalling production tubing between the producing formation and thesurface.

SUMMARY OF THE INVENTION

This invention relates to a method for primary cementing a well using acomposition of matter containing a polymerizable material and knowndrilling mud components which may be hardened to a cement by theapplication of a sufficient dose of radiation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 depicts a cross-sectional elevational of a typical rotary rigused in drilling oil and gas wells.

FIGS. 2A through 2D illustrate the various steps involved in a typicalproduction casing primary cementing job.

FIG. 2A is a cross-sectional elevation view showing the first step inthe displacement procedure.

FIG. 2B is a cross-sectional elevation view showing the second step inthe displacement procedure.

FIG. 2C is a cross-secional elevation view showing the final step in thedisplacement procedure.

FIG. 2D is a cross-sectional elevation view showing the perforationsused to produce hydrocarbons after the casing has been cemented. Theperforating tool is depicted in place hanging from a wireline.

FIGS. 3A through 3D illustrate the various steps involved in the primarycementing of production casing using the disclosed process.

FIG. 3A is a cross-sectional elevation view showing the first step inthe disclosed process.

FIG. 3B is a cross-sectional elevation view showing the second step inthe disclosed process.

FIG. 3C is a cross-sectional elevation view showing the irradiation stepin the disclosed process.

FlG. 3D is a cross-sectional elevation view showing the perforationsused to produce hydrocarbons after the casing has been cemented. Theperforating tool is depicted in place hanging from a wireline.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

As discussed above, the process of drilling a well using rotary drillingapparatus is a complicated and often lengthy process. A conventionaldrilling rig is shown in FIG. 1. The moving portion below ground level102 consists of a drill string and is made up of drill pipe sections104, drill collars 106, and a drill bit 108. The drill pipe sections 104and drill collars 106 are little more than strong threaded hollow pipesections which are rotated by equipment on the surface. Drilling collars106 have very thick walls and consequently are much heavier than similarsections of drill pipe. The drill collars 106 are intended to provide arelatively constant weight on drill bit 108, steady the drill string andkeep it in tension.

The drill string is turned by a kelly 110, a flat-sided hollow pipe,usually square or hexagonal in cross section, which is screwed into theuppermost section of drill pipe 104. The kelly is turned by a poweredrotary table 112 through a kelly bushing 114. The kelly bushing 114 fitsbetween the kelly 110 and the rotary table 112. It will slide up thekelly and out of engagement with the rotary table 112. The rotary table112 has a hole through its middle of sufficient size to allow passage ofthe drill pipe 104, drill collars 106, and the drill bit 108. That holehas a shape, often square, which will mesh with the kelly bushing 114.The drill string and kelly 110 are supported by rig hoisting equipmentincluding a traveling block 116 supported in the derrick 118. The drillstring rotates on swivel 120.

While the drill string is turning, drilling mud 121 is pumped into theswivel 120 from high pressure mud pumps (not shown) via a hose 122. Thedrilling mud proceeds down through the kelly 110, drill pipe sections104, drill pipe collars 106, and exits through nozzles in drill bit 108.The mud 121 then flows upwardly through the annular space between theborehole wall 124 and either the drill collars 106 or drill pipesections 104.

For purposes of illustration, the depicted well has a formation 126 witha formation pressure lower than the hydrostatic head of the drillingmud. The drilling mud is one having a clay such as bentonite dispersedtherein. Because of the difference in pressure between the annular spaceand the formation 126, a filter cake 128 of clay has been formed on theborehole wall.

In any event, the drilling mud 121 proceeds upwardly along the formation126, past the surface casing 130 and out a pipe 132 for subsequentseparation from the produced rock chips, reconstitution and recycling tothe well. The surface casing 130 is a casing similar to the productioncasings which will be discussed below. In most states the law requiresthat the surface casing extend from the surface to some stated depth,often 2000 feet. The surface casing isolates shallow aquifers from thewell. It is set by a casing shoe 134 and held in place by cement 136. Itis often easy to produce an acceptable surface casing cement job sincefew hydrocarbon formations are located near the surface to pollutelow-lying aquifers.

For simplicity of explanation, the apparatus associated withreconstituting the drilling mud is not depicted in the Figures norexplained in this specification. The apparatus is well known. Similarly,certain safety equipment of almost universal usage in the petroleumindustry, e.g., the blowout preventer stack, have been omitted from thediscussion here for the purpose of simplifying the overall explanationof the known drilling process.

Once the well is drilled to the desired depth, the drill string iswithdrawn from the borehole and the process of casing the well begins.

As discussed above, the primary purpose for installing cemented casingsin a wellbore is to isolate each of the formations from all otherformations penetrated by the well. Well casings are of two principaltypes, surface casing and production casing. Several different sizes ofcasing may be used in some wells. Surface casing illustrated by 130 inFIG. 1, is the first casing installed in a wellbore and extends from theground surface downwardly for a some set distance. Production casing istypically installed downhole adjacent the hydrocarbon formations to theproduced. The outside diameter of the production casing must be smallerthan the inside diameter of the surface casing so that the productioncasing can be inserted into the wellbore through the surface casing.Typically, both surface and production casing are cemented in place.

FIGS. 2A through 2D illustrate the various steps in a typical productioncasing primary cementing job after the casing is set in place. Thisprocess is equally applicable to the cementing of surface casings orother casings. In FIG. 2A, the wellbore passes down from the surfacethrough various subterranean formations including a fresh water aquifer202 and a producing formation 126.

As noted above, the well will typically have a surface casing 130 whichis held in place by a cement sheath 136. The cement sheath 136 may beformed by the same process as described below.

The production casing string found in FIG. 2A is made up of a casingshoe 204, float collar 206, and a number of joints of steel productioncasing 208. The purpose of the casing shoe 204 is to prevent distortionor abrasion of the production casing as it is forced past obstructionson the wall of the wellbore. Float collar 206 contains a back-pressureor check valve 210 which permits flow only in a downward direction. Anumber of casing centralizers 212 are attached at various points alongthe casing string in an attempt to maintain the string in the center ofthe wellbore. Similarly, scratchers 214 may be placed at intervals alongthe outside of the casing string. The scratchers 214 are used during thedisplacement process, in conjunction with rotation or reciprocation ofthe casing string, to dislodge gelled drilling mud or filter cake whichmay be adhering to the borehole wall. A small collar 216 is used toconnect adjacent sections of production casing 208.

FIG. 2A illustrates the primary step in the process of displacingdrilling mud with cement. Bottom plug 218 is inserted into the casingstring and a cement slurry 220 is pumped in above it. Bottom plug 218has a longitudinal hole 222 formed through its center, a number ofwipers 224 formed circumferentially about its outer surface and adiaphragm 226 attached to its upper surface to temporarily prevent theflow of cement through the hole 222. As the cement slurry 220 is pumpedinto the casing string it pushes the bottom plug 218 down toward thefloat collar 206. The movement of the bottom plug 218 in turn forcesdrilling mud 121 to flow down the casing string, out the casing shoe204, up the wellbore annulus, and out of the wellbore at the surface.Back-pressure valve 210 is held open by the flow of the drilling mud 121through float collar 206.

The following step in the process is shown in FIG. 2B. Bottom plug 218has been seated against the upper surface of float collar 206 and thediaphragm 226 broken. Cement slurry flows through the float collar 206,out of the casing shoe 204, and up the annulus. Back-pressure valve 210is held open by the downward movement of cement slurry 220. When aselected amount of cement slurry 220 has been pumped into the casingstring, a top plug 228 is inserted into the string. Top plug 228 has anumber of circumferential wipers 230 on its exterior. A displacementfluid 232, e.g., water, is introduced behind the top plug 228 and pumpeddown.

FIG. 2C illustrates the last step in the displacement process. Top plug228 has been forced down into contact with bottom plug 218 therebyclosing the longitudinal hole 222 through the bottom plug 218. Theaddition and pumping of displacement fluid 232 is then terminated andpressure on the displacement fluid 232 is released. Back-pressure valve210 in float collar 206 closes and thereby prevents cement slurry 220from flowing back up the inside of the casing string. Without closure ofthe back pressure valve 210 the high hydrostatic head of the cementslurry 220 would tend to push the displacement fluid 232 back up thecasing string. The cement slurry 220 may extend to the surface or it mayhave some drilling mud above it in the annulus. In any event, the cementslurry 220 is allowed to harden between the production casing and eitherthe surface casing 130 or the borehole wall. Upon hardening, the casingstring is firmly locked in place by the bond between the hardened cementsheath 234 and the casing string and by the various casingprotuberances, e.g., casing shoe 204, centralizers 212, float collar206, scratchers 214, and collars 216.

The method used to produce hydrocarbon fluids from the well is shown inFIG. 2D. After the cement sheath 234 has sufficiently hardened, theproduction casing 208 and the cement sheath 234 is perforated using aperforating tool 236 on a wire line 238 within the producing formation126. A perforating tool 236 typically fires into the producing formation126 upon a command sent over a wireline 238. This step creates a numberof perforations 240 through which hydrocarbon fluid may flow into thecasing string and up to the surface. If the process and apparatusoperate as designed, the hydrocarbon will flow only into the interior ofthe casing string and not to any other formation penetrated by the well.

As discussed above, one major problem in the creation of a fluid-tightcement sheath surrounding production casing and capable of isolatingvarious subterranean fluid-containing formations lies in the inabilityof the cement slurry to effectively displace the drilling mud found inthe borehole. The cement slurry does not always remove filter cake fromthose regions of the borehole where the formations absorb liquid. If asection of production casing resides near the borehole wall, thereexists a significant possibility that a quiescent zone of gelleddrilling mud will remain in the region where the production casingapproaches the borehole wall. The cement slurry simply flows around thisquiescent zone. Clearly, such anomalies create regions in which thecement is not capable of sealing the borehole wall.

The invention herein obviates these problems by the simple expedient ofeliminating the displacement step. Central to the invention is adrilling mud composition containing a polymerizable compound which maybe polymerized by exposure to a suitable radiation source. Instead ofattempting to displace the drilling mud from the well, the drilling mudis displaced only from the interior of the casing string and the mudremaining in the annulus is thereafter hardened.

The drilling mud composition may be made up of a conventional drillingmud and a polymerizable mixture.

Conventional drilling fluids, as discussed above, contain a number ofdiverse components; the proportion and type of each component isdetermined on the basis of need. The settable drilling mud disclosedherein may contain any of the components mentioned above as well as anyother which may be known in the art. The inventive drilling muddesirably is a water-based mud and should have chemical, physical, andrheological properties comparable to conventional drilling muds. The mudshould remain stable during and after the imposition of various forcesduring the drilling process. These may include shear forces encounteredin the mud pump or at the drill bit nozzles and the high temperaturesand pressures encountered within the wellbore. Organic polymers ormonomers having internal double bonds may be used in the mud formulationto hinder adverse effects on the physical characteristics of the mud athigher temperatures.

The cementitious material which results from the use of the inventivedrilling mud must share some of its physical properties with othercements known in the art. For instance, the cement must not havesignificant shrinkage after curing. The compressive strength of thecured cement must be sufficient for the well in which the cement isplaced. Finally, the time needed to cure the cement should not besignificantly different than those found in the art.

The inventive compositions which have been found to possess the desiredcharacteristics and may be solidified upon exposure to a radioactivesource generally contain a polymer containing one or more carbon-carbondouble bonds and monomeric crosslinking agents containing one or morecarbon-carbon double bonds. Functional groups substituted on either thepolymer or the crosslinking agent should be thermally stable at the usetemperatures.

The polymer containing at least one carbon-carbon double bond may be onewhich is cross-linkable using a radioactive source or may be one or moreselected from the group consisting of vinyl-, hydroxyl-,carboxyl-terminated butadiene acrylonitrile copolymers; methacrylicacid-methacrylate ester copolymers; polyethylene; polyacrylamide;polybutadiene; hydroxyl or carboxyl-terminated polybutadiene;hydroxyl-terminated epichlorohydrin polymers; polybutadiene oxide;polyvinyl alcohol; or polybutadiene acrylonitrile acrylic acidcopolymer. The polymer may be present in the settable drilling mudcomposition in amounts from 5% to 50% by weight and, in any event, in anamount sufficient to form an acceptable cementitious material uponapplication of sufficient irradiation.

The monomeric crosslinking agents containing at least one double bondmay be selected from materials which are capable of reacting with otherpolymers via radiation to produce an acceptable cement, acrylate-basedmonomers, or may be one or more selected from members of the groupconsisting of: ethylene glycol diacrylate, tetraethylene glycoldiacrylate, neopentylglycol diacrylate, tetrapropylene glycoldiacrylate, trimethylolpropane triacrylate, ethylene glycoldimethacrylate, triethylene glycol dimethacrylate, tetraethylene glycoldimethacrylate, trimethylolpropane trimethacrylate, dicyclopentenyloxyethyl methacrylate, divinyl benzene, 1,6-hexandiol diacrylate,tripropylene glycol diacrylate, diethyleneglycol divinyl ether. Themonomeric crosslinking agent is added in an amount, for instance, ofabout 15% to 70%, but in any event sufficient to produce an acceptablecementitious material upon application of sufficient radiation.

Table I below lists a series of compositions made using the followingprocedure to demonstrate the attainable compressive strengths ofsettable drilling fluids made according to the invention disclosedherein.

A slurry for the compositions in Table I was made by mixing, whilestirring, 30 parts by weight of bentonite into 339 parts by weight tapwater. The resulting mixture was stirred for 30 minutes. Two parts byweight of chrome lignosulfonate (tradename--SPERSENE) was added and themixture stirred for five minutes. Sodium hydroxide, in an amount of 0.6to 0.7 parts by weight, was added.

The bentonite-chrome lignosulfonate slurry was then mixed with thepolymers and cross-linking agents listed in Table I to produce a polymerslurry. The Fann rheology characteristics of the slurry were measured at300 rpm and 600 rpm. Samples were then irradiated with a Co-60 source atthe noted rates and total dose to produce cured solids. The resultingcompressive strengths of specimens having about 0.8 square inch crosssection and a height of about 0.5 inch were then measured.

                                      TABLE I                                     __________________________________________________________________________    Base     Add'l                                                                              Cross-Linking                                                                        Bentonite Fann                Compressive                Polymer  Polymer                                                                            Agent  Cr--lignosulfonate                                                                      Viscosity Dose Rate                                                                           Dose                                                                              Strength                   Sample                                                                            (g.) (g.) (g.)   Slurry (g.)                                                                             300 rpm                                                                            600 rpm                                                                            (MR/hr)                                                                             (MR)                                                                              (psi.)                     __________________________________________________________________________    I-1 VTBN E-1194                                                                             TMPTMA (200)     High --   1.0   0.5  670.2                         (40) (8)  (148)                                                           I-2 VTBN E-1194                                                                             TMPTMA "         "    --   "     1.0 1280.8                         (40) (8)  (148)                                                           I-3 VTBN E-1194                                                                             TMPTMA "         "    --   "     2.0 1767.0                         (40) (8)  (148)                                                           I-4 VTBN E-1194                                                                             TMPTMA "         "    --   2.0   0.5 466.5                          (40) (8)  (148)                                                           I-5 VTBN E-1194                                                                             TMPTMA "         "    --   "     1.0 1412.9                         (40) (8)  (148)                                                           I-6 VTBN E-1194                                                                             TMPTMA "         "    --   "     2.0 1575.5                         (40) (8)  (148)                                                           I-7 VTBN E-1194                                                                             TMPTA  (200)     117  235  1.0   0.5 4594.3                         (40) (8)  (644)                                                           I-8 VTBN E-1194                                                                             TMPTA  "         "    "    "     1.0 6780.8                         (40) (8)  (644)                                                           I-9 VTBN E-1194                                                                             TMPTA  "         "    "    "     2.0 7440.2                         (40) (8)  (644)                                                           I-10                                                                              VTBN E-1194                                                                             TMPTA  "         "    "    2.0   0.5 2358.6                         (40) (8)  (644)                                                           I-11                                                                              VTBN E-1194                                                                             TMPTA  "         "    "    "     1.0 4662.0                         (40) (8)  (644)                                                           I-12                                                                              VTBN E-1194                                                                             TMPTA  "         "    "    "     2.0 6062.3                         (40  (8)  (644)                                                           I-13                                                                              VTBN E-1194                                                                             TMPTA  (200)     104  220  1.0   0.5 7397.1                         (40) (8)  (144)                                                                         QM657                                                                         (496)                                                           I-14                                                                              VTBN E-1194                                                                             TMPTA  "         "    "    "     1.0 6681.3                         (40) (8)  (144)                                                                         QM657                                                                         (496)                                                           I-15                                                                              VTBN E-1194                                                                             TMPTA  "         "    "    "     2.0 8626.5                         (40) (8)  (144)                                                                         QM657                                                                         (496)                                                           I-16                                                                              VTBN E-1194                                                                             TMPTA  "         "    "    2.0   0.5 2751.2                         (40) (8)  (144)                                                                         QM657                                                                         (496)                                                           I-17                                                                              VTBN E-1194                                                                             TMPTA  "         "    "    "     1.0 8542.1                         (40) (8)  (144)                                                                         QM657                                                                         (496)                                                           I-18                                                                              VTBN E-1194                                                                             TMPTA  "         "    "    "     2.0 9633.5                         (40) (8)  (144)                                                                         QM657                                                                         (496)                                                           __________________________________________________________________________     NOTES:                                                                        VTBN vinylterminated butadiene acrylonitrile copolymerB. F. Goodrich HYCA     VTBN                                                                          E1194 methacrylic acidmethacrylate ester copolymerRohm and                    TMPTMA trimethylolpropane trimethacrylate                                     QM657 dicyclopentenyl oxyethyl methacrylate                              

Additional settable drilling fluids were mixed using the base polymers,additional polymers and cross-linking agents listed in Table II by usingthe procedure outlined above with respect to Table I. The resultingpolymer-containing slurries were irradiated at the noted rates and thecompressive strengths measured.

                                      TABLE II                                    __________________________________________________________________________                          Bentonite                                                   Base  Add'l                                                                              Cross-Linking                                                                        Ferrochrome       Compressive                               Polymer                                                                             Polymer                                                                            Agent  Lignosulfonate                                                                        Dose Rate                                                                           Dose                                                                              Strength                              Sample                                                                            (g.)  (g.) (g.)   Slurry (g.)                                                                           (MR/hr)                                                                             (MR)                                                                              (psi.)                                __________________________________________________________________________    II-1                                                                              PE    E-1194                                                                             TMPTMA (100)   1.0   1.0 3442                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-2                                                                              PE    E-1194                                                                             TMPTMA "       "     5.0 4494                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-3                                                                              PE    E-1194                                                                             TMPTMA "       "     10.0                                                                              5086                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-4                                                                              PE    E-1194                                                                             TMPTMA "       2.0   1.0 3099                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-5                                                                              PE    E-1194                                                                             TMPTMA "       "     5.0 4959                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-6                                                                              PE    E-1194                                                                             TMPTMA "       "     10.0                                                                              6345                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-7                                                                              P-35  E-1194                                                                             TMPTMA (100)   1.0   1.0 4876                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-8                                                                              P-35  E-1194                                                                             TMPTMA "       "     5.0 --                                        (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-9                                                                              P-35  E-1194                                                                             TMPTMA "       "     10.0                                                                              5004                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-10                                                                             P-35  E-1194                                                                             TMPTMA "       2.0   1.0 2904                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-11                                                                             P-35  E-1194                                                                             TMPTMA "       "     5.0 4292                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-12                                                                             P-35  E-1194                                                                             TMPTMA "       "     10.0                                                                              3882                                      (74)  (4)  (148)                                                                    VTBN                                                                          (65.2)                                                              II-13                                                                             HTBN  E-1194                                                                             TMPTMA (100)   1.0   1.0 1014                                      (47)  (4)  (148)                                                          II-14                                                                             HTBN  E-1194                                                                             TMPTMA "       "     5.0 1508                                      (47)  (4)  (148)                                                          II-15                                                                             HTBN  E-1194                                                                             TMPTMA "       "     10.0                                                                              2175                                      (47)  (4)  (148)                                                          II-16                                                                             HTBN  E-1194                                                                             TMPTMA "       2.0   1.0 --                                        (47)  (4)  (148)                                                          II-17                                                                             HTBN  E-1194                                                                             TMPTMA "       "     5.0  899                                      (47)  (4)  (148)                                                          II-18                                                                             HTBN  E-1194                                                                             TMPTMA "       "     10.0                                                                              1470                                      (47)  (4)  (148)                                                          II-19                                                                             CTBN  E-1194                                                                             TMPTMA (100)   1.0   1.0  661                                      (75)  (4)  (148)                                                          II-20                                                                             CTBN  E-1194                                                                             TMPTMA "       "     5.0  991                                      (75)  (4)  (148)                                                          II-21                                                                             CTBN  E-1194                                                                             TMPTMA "       "     10.0                                                                              1469                                      (75)  (4)  (148)                                                          II-22                                                                             CTBN  E-1194                                                                             TMPTMA "       2.0   1.0 --                                        (75)  (4)  (148)                                                          II-23                                                                             CTBN  E-1194                                                                             TMPTMA "       "     5.0 2806                                      (75)  (4)  (148)                                                          II-24                                                                             CTBN  E-1194                                                                             TMPTMA "       "     10.0                                                                              1401                                      (75)  (4)  (148)                                                          II-25                                                                             RICON153                                                                            E-1194                                                                             TMPTMA (100)   1.0   1.0 --                                        (74)  (4)  (148)                                                          II-26                                                                             RICON153                                                                            E-1194                                                                             TMPTMA "       "     5.0  678                                      (74)  (4)  (148)                                                          II-27                                                                             RICON153                                                                            E-1194                                                                             TMPTMA "       "     10.0                                                                              1179                                      (74)  (4)  (148)                                                          II-28                                                                             RICON153                                                                            E-1194                                                                             TMPTMA "       2.0   1.0 1647                                      (74)  (4)  (148)                                                          II-29                                                                             RICON153                                                                            E-1194                                                                             TMPTMA "       "     5.0 2581                                      (74)  (4)  (148)                                                          II-30                                                                             RICON153                                                                            E-1194                                                                             TMPTMA "       "     10.0                                                                              2338                                      (74)  (4)  (148)                                                          II-31                                                                             CTB   E-1194                                                                             TMPTMA (100)   1.0   1.0 --                                        (74)  (4)  (148)                                                          II-32                                                                             CTB   E-1194                                                                             TMPTMA "       "     5.0 --                                        (74)  (4)  (148)                                                          II-33                                                                             CTB   E-1194                                                                             TMPTMA "       "     10.0                                                                               743                                      (74)  (4)  (148)                                                          II-34                                                                             CTB   E-1194                                                                             TMPTMA "       2.0   1.0  268                                      (74)  (4)  (148)                                                          II-35                                                                             CTB   E-1194                                                                             TMPTMA "       "     5.0  490                                      (74)  (4)  (148)                                                          II-36                                                                             CTB   E-1194                                                                             TMPTMA "       "     10.0                                                                               647                                      (74)  (4)  (148)                                                          __________________________________________________________________________     NOTES:                                                                        PE polyethylene (3500MW)Allied Chemical                                       P35 polyacrylamideAmerican Cyanamid                                           HTBN hydroxylterminated butadiene acrylonitrile copolymerB. F. Goodrich       HYCAR HTBN                                                                    CTBN carboxylterminated butadiene acrylonitrile copolymerB. F. Goodrich       HYCAR CTBN                                                                    VTBN vinylterminated butadiene acrylonitrile copolymerB. F. Goodrich HYCA     VTBN                                                                          E1194 methacrylic acidmethacrylate ester copolymerRohm and Haas               TMPTMA trimethylolpropane trimethacrylate                                     RICON 153 polybutadieneColorado Chemical Specialities, Inc.                   CTB carboxylterminated polybutadiene (28,000MW)B. F. Goodrich HYCAR CTB  

Other compositions were produced by first mixing 70 parts by weight ofwater with five parts by weight of bentonite and continuously stirringfor 20 minutes. To this mixture was then added 25 parts by weight baritewhile stirring. The crosslinking agent was then added to 150 grams ofthe resulting slurry and stirred for five minutes. The base polymer thenwas mixed in while stirring. Stirring was continued for 10 minutes. Fannrheology data were taken. The samples were loaded into a sample holderand exposed to a Co-60 source. Each sample received 2MR total dose at arate of 2MR/hr.

                                      TABLE III                                   __________________________________________________________________________        Base Cross-Linking                                                                        Bentonite Barite                                                                       Fann-Plastic                                                                         Fann-Yield   Compressive                          Polymer                                                                            Agent  Slurry   Viscosity                                                                            Point        Strength                         Sample                                                                            (g.) (g.)   (g.)     (cp)   (lb/100 ft.sup.2)                                                                   Appearance                                                                           (psi.)                           __________________________________________________________________________    Slurry                                                                            --   --     --        7     10    --     --                               III-1                                                                             HTB-1                                                                              TRPGDA 150      11     11    G      141                                   (5) (45)                                                                 III-2                                                                             HTB-1                                                                              TRPGDA "         6     15    G      98                                   (10) (40)                                                                 III-3                                                                             HTB-1                                                                              TRPGDA "         8      9    G      76                                   (15) (35)                                                                 III-4                                                                             HTB-1                                                                              TRPGDA "         3     19    F      43                                   (20) (30)                                                                 III-5                                                                             HTB-1                                                                              TMPTA  "         9      7    C      --                                    (5) (45)                                                                 III-6                                                                             HTB-1                                                                              TMPTA  "         9      5    C      --                                   (10) (40)                                                                 III-7                                                                             HTB-1                                                                              TMPTA  "         9      4    C      --                                   (15) (35)                                                                 III-8                                                                             HTB-1                                                                              TMPTA  "         8      5    C      --                                   (20) (30)                                                                 III-9                                                                             HTB-1                                                                              DVDEG  "        23     18    A      --                                   (10) (10)                                                                 III-10                                                                            HTB-1                                                                              DVDEG  "        20     17    A      --                                   (20) (30)                                                                 III-11                                                                            HTB-1                                                                              TTEGDA "        30     22    F      --                                   (10) (40)                                                                 III-12                                                                            HTB-1                                                                              HDODA  "        --     --    F      --                                   (10) (40)                                                                 III-13                                                                            HTB-2                                                                              TRPGDA "        51     37    G      168                                  (10) (40)                                                                 III-14                                                                            HTB-2                                                                              TRPGDA "        30     84    G      176                                  (10) (40)                                                                 III-15                                                                            HTB-2                                                                              TRPGDA "        48     118   G      113                                  (20) (30)                                                                 III-16                                                                            HTB-2                                                                              TTEGDA "        40     52    G      68                                   (10) (40)                                                                 III-17                                                                            HTB-2                                                                              TTEGDA "        40     36    G      26                                   (20) (30)                                                                 III-18                                                                            HTB-3                                                                              TTEGDMA                                                                              "        23      7    G      81                                    (5) (45)                                                                 III-19                                                                            HTB-3                                                                              TTEGDMA                                                                              "        14     15    G      62                                   (10) (40)                                                                 III-20                                                                            HTB-3                                                                              TTEGDMA                                                                              "        19      9    G      97                                   (10) (50)                                                                 III-21                                                                            HTB-3                                                                              TTEGDMA                                                                              "        15     16    --     --                                   (10) (60)                                                                 III-22                                                                            HTB-4                                                                              TTEGDMA                                                                              "        19     11    G      94                                    (5) (45)                                                                 III-23                                                                            HTB-5                                                                              TTEGDMA                                                                              "        23      1    G      135                                   (5) (45)                                                                 III-24                                                                            HTBN TRPGDA "        13     11    F      43                                    (5) (45)                                                                 III-25                                                                            (10) (40)   "        15      7    G      144                              III-26                                                                            (15) (35)   "        15      9    G      163                              III-27                                                                            (20) (30)   "        10     10    F      38                               III-28                                                                            HTBN TMPTA  "        13      7    E      --                                    (5) (45)                                                                 III-29                                                                            (10) (40)   "        15      6    E      --                               III-30                                                                            (15) (35)   "        16      9    E      --                               III-31                                                                            (20) (30)   "        16      6    E      --                               III-32                                                                            HTBN TTEGDA "        35     52    --     24                                   (10) (40)                                                                 III-33                                                                            HTBN TTEGDA "        39     50    --     27                                   (20) (30)                                                                 III-34                                                                            HTBN HDODA  "        50     48    --     51                                   (10) (40)                                                                 III-35                                                                            VTBNX                                                                              TRPGDA "        28     46    F      49                                    (5) (45)                                                                 III-36                                                                            (10) (40)   "        25     32    G      92                               III-37                                                                            (15) (35)   "        20     22    G      70                               III-38                                                                            (20) (30)   "        20     22    F      38                               III-39                                                                            VTBNX                                                                              TMPTA  "        16     11    E      --                                    (5) (45)                                                                 III-40                                                                            (10) (40)   "        20     18    E      --                               III-41                                                                            (15) (35)   "        25     31    E      --                               III-42                                                                            (20) (30)   "        24     38    E      --                               III-43                                                                            VTBNX                                                                              DVDEG  "        25     14    A      --                                   (10) (40)                                                                 III-44                                                                            (20) (30)   "        39     11    A      --                               III-45                                                                            VTBNX                                                                              TTEGDA "        42     42    --     65                                   (10) (40)                                                                 III-46                                                                            (10) (40)   "        41     35    --     --                               III-47                                                                            (20) (30)   "        43     50    --     35                               III-48                                                                            VTBNX                                                                              HDODA  "        61     127   --     74                                   (10) (40)                                                                 III-49                                                                            HTEC-1                                                                             TTEGDA "        41     59    --     28                                   (10) (40)                                                                 III-50                                                                            (10) (40)   "        52     71    --     47                               III-51                                                                            HTEC-1                                                                             TRPGDA "        0/5    --    F      --                                   (10) (40)                                                                 III-52                                                                            HTEC-2                                                                             TTEGDA "        38     51    --     21                                   (10) (40)                                                                 III-53                                                                            (10) (40)   "        47     51    --     25                               III-54                                                                            (20) (30)   "        47     52    --     25                               III-55                                                                            HTEC-2                                                                             TRPGDA "        0/5    --    --     29                                   (10) (40)                                                                 III-56                                                                            PBO  TMPTA  "        27     16    E      --                                    (5) (45)                                                                 III-57                                                                            (10) (40)   "        27     24    E      --                               III-58                                                                            (15) (35)   "        24     22    E      --                               III-59                                                                            PBO  TRPGDA "        31     19    G      133                                   (5) (45)                                                                 III-60                                                                            (10) (40)   "        32     26    G      109                              III-61                                                                            (15) (35)   "        32     36    G      82                               III-62                                                                            PBO  TTEGDMA                                                                              "        31     13    G      183                                   (5) (45)                                                                 III-63                                                                            (10) (40)   "        33     20    G      218                              III-64                                                                            (15) (35)   "        25     15    G      108                              III-65                                                                            PVA-1                                                                              TMPTA  "        55     55    C      --                                    (5) (45)                                                                 III-66                                                                            (10) (40)   "        88     91    B      --                               III-67                                                                            (15) (35)   "        180    186   D      --                               III-68                                                                            PVA-1                                                                              TRPGDA "        --     --    B      --                                    (5) (45)                                                                 III-69                                                                            PVA-1                                                                              TTEGDMA                                                                              "        48     41    B      --                                    (5) (45)                                                                 III-70                                                                            PBAA TRPGDA "        57     177   G      235                                   (5) (45)                                                                 III-71                                                                            PBAA TTEGDMA                                                                              "        43     135   G      289                                   (5) (45)                                                                 III-72                                                                            PBAA TMPTA  "        36     44    G      122                                   (5) (45)                                                                 __________________________________________________________________________     NOTES:                                                                        (1) HTB1 hydroxylterminated butadiene polymerARCO Polybd R45HT                HTB2 hydroxylterminated butadiene polymerB. F. Goodrich Hycar 2000X 166       HTB3 hydroxylterminated butadiene polymerPolysciences, Inc. 4357              HTB4 hydroxylterminated butadiene polymerPolysciences, Inc. 6508              HTB5 hydroxylterminated butadiene polymerPolysciences, Inc. 6079              HTBN hydroxylterminated butadiene acrylonitrile polymerB. F. Goodrich         HYCAR 1300 × 29                                                         VTBNX vinylterminated butadiene acrylonitrile polymer with pendant vinyl      groupsB. F. Goodrich HYCAR 1300 × 23                                    HTEC1 hydroxylterminated epichlorohydrin polymerB. F. Goodrich Hydrin 10      × 1                                                                     HTEC2 hydroxylterminated epichlorohydrin polymerB. F. Goodrich Hydrin 10      × 2                                                                     PBO polybutadiene oxidePolysciences, Inc. 5434                                PVA1 polyvinyl alcohol (125,000mw)Aldrich 18,9359                             PBAA polybutadiene acrylonitrile acrylic acid copolymerPolysciences, Inc.     9757                                                                          TRPGDA tripropyleneglycol diacrylateCelanese                                  TMPTA trimethylopropane triacrylateCelanese                                   DVDEG diethyleneglycol divinyl etherPolysciences, Inc.                        TTEGDA tetraethyleneglycol diacrylateCelanese                                 HDODA 1,6hexanediol diacrylateCelanese                                        TTEGDMA tetraethyleneglycol dimethacrylate                                    (2) Codes for cured solid appearance:                                         A -- no apparent cure                                                         B -- very softmushy                                                           C -- soft puttylike solid                                                     D -- soft crumbly solid                                                       E -- firm crumbly solid                                                       F -- hard crumbly solid                                                       G -- firm elastic solid                                                  

FIGS. 3A through 3D disclose the most desirable method of using thesettable drilling mud composition disclosed herein in a primarycementing job after production casing is set in place. The process alsomay be used in cementing surface casings and other casings.

In FIG. 3A the well passes down from the surface and through varioussubterranean formations including a fresh water aquifer 202 and aproducing formation 126. The well should have a surface casing 130 whichis held in place by a cement sheath 136. The cement sheath 136 may beformed by using this process.

The production casing string found in FIG. 3A desirably is made up of afloat shoe 302 and a number of joints of steel production casing 208joined by collar 216. The float shoe 302 has the same function as do thecombination of the casing shoe 204 and float collar 206 shown in FIGS.2A through 2D. Since the cement of the invention is not selfsetting, theplacement of the float shoe 302 is very low in the casing string toallow, as discussed below, adequate irradiation of all the settabledrilling mud. The purpose of the float shoe 302 is multiple. It preventsdistortion or abrasion of the production casing as it is introduced intothe well and forced past obstructions on the wall of the wellbore. Floatshoe 302 contains a back-pressure or check valve 304 which permits flowonly in a downward direction. The lower end of the float shoe, oftencalled the snout or guide 306, is usually made of cement or cast iron. Anumber of casing centralizers 212 may be attached at intervals along thecasing string to maintain the string in the center of the wellbore. Thecentralizers may have the effect of slightly bending the casing stringso that it follows the general path of the borehole. Since in using thisprocess no benefit is gained in removing filter cakes or gelled mud fromthe annular space, the traditional scratchers may be omitted form theexterior of the casing.

FIG. 3A illustrates the initial step in the process, i.e., displacingsettable drilling mud 308 from the interior of the casing string. Aclosing plug 310 is inserted into the casing string. The settabledrilling mud 308 is below the closing plug 310 and outside the casingstring in the annular space. A displacement fluid 312 is pumped inbehind the closing plug 310. The displacement fluid 312 may be anyconvenient fluid, e.g. water. As the displacement fluid 312 is pumpedinto the casing string, it pushes the closing plug 310 down. The closingplug 310, in turn, displaces the settable drilling mud 308 down thecasing string, out the float shoe 302, up the annular space, and theexcess is collected at the surface. The wipers 314 on the exterior ofthe closing plug 310 provide a barrier between the two fluids in thecasing string and wipe the settable drilling mud from the casingstring's interior surface.

FIG. 3B shows the completion of the settable drilling mud displacementstep. The closing plug 310 has been pumped all the way down to theopening of float shoe 302. The pressure on the displacement fluid 312has been released and the backpressure valve 304 is in its sealingposition preventing upward flow of the denser settable drilling fluid308. The closing plug 310 may have, incorporated in its mating end,mechanical latch means which attach permanently to float shoe 302.

FIG. 3C discloses the step of irradiating the settable drilling mud 308thereby causing it to set. The radioactive source 316 may be composed ofany suitable radioactive material although the preferable materials aregamma ray emitters such as Cobalt-60, Zinc-65, Cesium-137, Tantalum-182,and Iridium-192. The most preferable source is Cobalt-60, because of itsready availability, in an amount capable of providing a dose rate ofabout 0.1 to about 10.0 Mrad/hour in the the settable drilling mud foundin the particular well geometry. The total dosage may range from 0.1 to50 Mrad. Lower dosages are preferred in that, depending upon the polymersystem chosen, undesirable chainbreaking or scission reactions may occurmore readily at the higher dosages and rates.

As noted above, the pressure on the casing string is kept at a low leveland the irradiation tool 316 is inserted into the casing string on awire line 318. The tool is lowered to the region of the float shoe 302and retrieved. The rate of insertion and withdrawal is such that thetotal dosage received by each incremental volume of mud is sufficient topolymerize the polymerizable material in the settable drilling mud 308,and thereby form a cementitious solid sheath 320. Multiple passes arealso contemplated. The casing string is then firmly locked in place bythe various casing protuberances, e.g., float shoe 302, centralizers212, and collars 216.

After the settable drilling mud has hardened sufficiently, the well maybe perforated in the manner shown in FIG. 3D. The production casing 208and the cementitious solid sheath 320 are perforated using a perforatingtool 236 on a wire line 238 in the region of the producing formation 126in the same general manner as the perforating step shown in FIG. 2D anddiscussed above. The perforating tool 236 creates a number ofperforations 240 through which hydrocarbon fluids may flow into thecasing string and up to the surface.

It should be understood that the foregoing disclosure and descriptionare only illustrative and explanatory of the invention. Various changesin the components of the composition and method of using thatcomposition as well as in the details of the illustrated process may bemade within the scope of the appended claims without departing from thespirit of the invention.

I claim as my invention:
 1. A method for drilling and primary cementinga well comprising the steps of:drilling a well using a hollow drillstring having a drill bit with at least one orifice communicatingbetween the inside of the hollow drill string and the outside andlocated at the lower end of said drill string so as to produce awellbore, circulating, while drilling, a drilling fluid comprising: atleast one polymeric material containing at least one double bond andcapable of being cross-linked with a monomeric cross-linking agent usinga radioactive source, at least one monomeric cross-linking agentcontaining at least one double bond, water, and at least one clay, downthe inside of said drill string and out said at least one orifice,withdrawing said drill string from said wellbore, installing a floatshoe having an upper seating surface on the lower end of a first sectionof well casing, assembling a casing string by sequentially attachingadditional sections of casing to said first section of well casing andinserting the casing string farther into the wellbore, inserting aclosing plug into said casing string, said closing plug havingcircumferential wipers and a surface adapted to contact said upperseating surface on said float shoe, moving said closing plug down saidcasing string by pumping displacement fluid into said casing stringabove said closing plug so as to substantially displace said drillingfluid from the inside of said casing string, and inserting a radioactivesource into the casing string and passing it along the length of thecasing string so as to set said drilling fluid into a cementitiousmaterial.
 2. The process of claim 1 wherein said at least one polymericmaterial is at least one selected from the group consisting of: vinyl-,hydroxyl-, carboxyl-terminated butadiene acrylonitrile copolymers,methacrylic acid-methacylate ester copolymers; polyethylene;polyacrylamide; polybutadiene; hydroxyl- or carboxyl-terminatedpolybutadiene; hydroxyl-terminated epichlorohydrin polymers;polybutadiene oxide; polyvinyl alcohol; or polybutadiene acrylonitrileacrylic acid copolymer.
 3. The process of claim 1 wherein said at leastone monomeric cross-linking agent is at least one selected from thegroup consisting of: ethylene glycol diacrylate, tetraethylene glycoldiacrylate, neopentyl glycol diacrylate, tetrapropylene glycoldiacrylate, trimethylolpropane triacrylate, ethylene glycoldimethacrylate, triethylene glycol dimethacrylate, tetraethylene glycoldimethacrylate, trimethylolpropane trimethacrylate, dicyclopentenyloxyethyl methacrylate, divinyl benzene, 1,6-hexandiol diacrylate,tripropylene glycol diacrylate, diethylene glycol divinyl ether.
 4. Theprocess of claim 1 wherein said drilling fluid also contains at leastone weighting agent selected from the group consisting of barite, ironore, lead sulfide ferrous oxide, and titanium dioxide.
 5. The process ofclaim 1 wherein said at least one clay is bentonite or attapulgite. 6.The process of claim 1 wherein said at least one polymeric materialcomprises polybutadiene oxide and said at least one monomericcross-linking agent comprises tripropylene glycol diacrylate.
 7. Theprocess of claim 1 wherein said displacement fluid is water.
 8. Theprocess of claim 1 wherein said radioactive source is passed along thelength of said casing string more than one time.
 9. The process of claim1 wherein said radioactive source is of a size and is passed along thelength of said casing string so as to produce a dose rate on the outsideof the casing string between about 0.1 to about 10.0 Mrad/hr.
 10. Theprocess of claim 1 wherein said radioactive source is of a size and ispassed along the length of said casing string so as to produce a totaldosage on the outside of the casing string between about 0.1 and 50Mrads.
 11. The process of claim 1 wherein the radioactive sourcecomprises Cobalt-60.
 12. The wellbore cementitious sheath made by theprocess of claim
 1. 13. A method for primary cementing a well having awellbore comprising the steps of:inserting a casing string having adiameter less than that of the wellbore into said wellbore containing adrilling fluid comprising:at least one polymeric material containing atleast one double bond and capable of being cross-linked with a monomericcross-linking agent using a radioactive source, at least one monomericcross-linking agent containing at least one double bond, water, and atleast one clay, displacing said drilling fluid from the interior of thecasing string into the annular space between the wellbore and theoutside of the casing string, inserting a radioactive source into thecasing string and passing it along the length of the casing string so asto set said drilling fluid into a cementitious material.
 14. The processof claim 13 wherein said at least one polymeric material is at least oneselected from the group consisting of: vinyl-, hydroxyl-,carboxyl-terminated butadiene acrylonitrile copolymers; polyethylene;polyacrylamide; polybutadiene; hydroxyl- or carboxyl-terminatedpolybutadiene; hydroxyl-terminated epichlorohydrin polymers;polybutadiene oxide; polyvinyl alcohol; or polybutadiene acrylonitrileacrylic acid copolymer.
 15. The process of claim 13 wherein said atleast one monomeric cross-linking agent is at least one selected fromthe group consisting of: ethylene glycol diacrylate, tetraethyleneglycol diacrylate, neopentyl glycol diacrylate, tetrapropylene glycoldiacrylate, trimethylolpropane triacrylate, ethylene glycoldimethacrylate, triethylene glycol dimethacrylate, tetraethylene glycoldimethacrylate, trimethylolpropane trimethacrylate, dicyclopentenyloxyethyl methacrylate, divinyl benzene, 1,6-hexandiol diacrylate,tripropylene glycol diacrylate, diethyleneglycol divinyl ether.
 16. Theprocess of claim 13 wherein said drilling fluid also contains at leastone weighting agent selected from the group consisting of barite, ironore, lead sulfide, ferrous oxide, and titanium dioxide.
 17. The processof claim 13 wherein said at least one clay is bentonite or attapulgite.18. The composition of claim 13 wherein said at least one polymericmaterial comprises polybutadiene oxide and said at least one monomericcross-linking agent comprises tripropylene glycol diacrylate.
 19. Theprocess of claim 13 wherein said radioactive source is passed along thelength of said casing string more than one time.
 20. The process ofclaim 13 wherein said radioactive source is of a size and is passedalong the length of said casing string so as to produce a dose rate onthe outside of the casing string between about 0.1 to about 10.0Mrad/hr.
 21. The process of claim 13 wherein said radioactive source isof a size and is passed along the length of said casing string so as toproduce a total dosage on the outside of the casing string between about0.1 and 50 Mrads.
 22. The process of claim 13 wherein the radioactivesource comprises Cobalt-60.
 23. The cementitious material made by theprocess of claim
 13. 24. A method for drilling and primary cementing awell comprising the steps of:drilling a well using a hollow drill stringhaving a drill bit with at least one orifice communicating between theinside of the hollow drill string and the outside and located at thelower end of said drill string so as to produce a wellbore, circulating,while drilling, a drillig fluid comprising:at least one polymericmaterial containing at least one double bond and capable of beingcross-linked with a monomeric cross-linking agent using a radioactivesource, said polymeric material being selected from the group consistingof: vinyl-, hydroxyl-, carboxyl-terminated butadiene acrylonitrilecopolymers, methacrylic acid-methacrylate ester copolymers;polyethylene; polyacrylamide; polybutadiene; hydroxyl- orcarboxyl-terminated polybutadiene; hydroxyl-terminated epichlorohydrinpolymers; polybutadiene oxide; polyvinyl alcohol; or polybutadieneacrylonitrile acrylic acid copolymer, at least one monomericcross-linking agent containing at least one double bond and beingselected from the group consisting of: ethylene glycol diacrylate,tetraethylene glycol diacrylate, neopentyl glycol diacrylate,tetrapropylene glycol diacrylate, trimethylolpropane triacrylate,ethylene glycol dimethacrylate, triethylene glycol dimethacrylate,tetraethylene glycol dimethacrylate, trimethylolpropane trimethacrylate,dicyclopentenyl oxyethyl methacrylate, divinyl benzene, 1,6-hexandioldiacrylate, tripropylene glycol diacrylate, diethyleneglycol divinylether, water, and at least one clay, down the inside of said drillstring and out said at least one orifice, withdrawing said drill stringfrom said wellbore, installing a float shoe having an upper seatingsurface on the lower end of a first section of well casing, assembling acasing string by sequentially attaching additional sections of casing tosaid first section of well casing and inserting the casing stringfarther into the wellbore, inserting a closing plug into said casingstring, said closing plug having circumferential wipers and a surfaceadapted to contact said upper seating surface on said float shoe, movingsaid closing plug down said casing string by pumping displacement fluidinto said casing string above said closing plug so as to substantiallydisplace said drilling fluid from the inside of said casing string,inserting a radioactive source into the casing string and passing italong the length of the casing string so as to set and drilling fluidinto a cementitious material.
 25. A method for primary cementing a wellhaving a wellbore comprising the steps of:inserting a casing stringhaving a diameter less than that of the wellbore into said wellborecontaining a drilling fluid comprising:at least one polymeric materialcontaining at least one double bond and capable of being cross-linkedwith a monomeric cross-linking agent using a radioactive source, saidpolymeric material being selected from the group consisting of: vinyl-,hydroxyl-, carboxyl-terminated butadiene acrylonitrile copolymers;polyethylene; polyacrylamide; polybutadiene; hydroxyl- orcarboxyl-terminated polybutadiene, hydroxyl-terminated epichlorohydrinpolymers; polybutadiene oxide; polyvinyl alcohol; or polybutadieneacrylonitrile acrylic acid copolymer, at least one monomericcross-linking agent containing at least one double bond and beingselected from the group consisting of: ethylene glycol diacrylate,tetraethylene glycol diacrylate, neopentyl glycol diacrylate,tetrapropylene glycol diacrylate, trimethylolpropane triacrylate,ethylene glycol dimethacrylate, triethylene glycol dimethacrylate,tetraethylene glycol dimethacrylate, trimethylolpropane trimethacrylate,dicyclopentenyl oxyethyl methacrylate, divinyl benzene, 1,6-hexandioldiacrylate, tripropylene glycol diacrylate, diethyleneglycol divinylether, water, and at least one clay, displacing said drilling fluid fromthe interior of the casing string into the annular space between thewellbore and the outside of the casing string, inserting a radioactivesource into the casing string and passing it along the length of thecasing string so as to set said drilling fluid into a cementitiousmaterial.